Note: Descriptions are shown in the official language in which they were submitted.
Attorney Docket No. 38496.431FF01
Customer No. 27683
DEEPSET RECEIVER FOR DRILLING APPLICATION
BACKGROUND OF THE DISCLOSURE
[0001] The
present disclosure relates in general to logging tools and particularly to
receivers
used in electromagnetic logging tools.
[0002]
Measurement-while-drilling (MWD) tools and logging-while-drilling (LWD) tools
capture information during the process of drilling a wellbore. However, the
ability of current
receivers to receive signals using MWD tools typically provide drilling
parameter information
such as weight on the bit, torque, temperature, pressure, direction, and
inclination. LWD tools
typically provide formation evaluation measurements such as resistivity,
porosity, and NMR
distributions (e.g., Ti and T2). MWD and LWD tools often have characteristics
common to
wireline tools (e.g., transmitting and receiving antennas), but MWD and LWD
tools must be
constructed to not only endure but to operate in the harsh environment of
drilling.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] The
present disclosure is best understood from the following detailed description
when read with the accompanying figures. It is emphasized that, in accordance
with the standard
practice in the industry, various features are not drawn to scale. In fact,
the dimensions of the
various features may be arbitrarily increased or reduced for clarity of
discussion.
[0004] FIG.
1 is an illustration of an exemplary drilling telemetry system in a
subterranean
formation according to one or more aspects of the present disclosure.
[0005] FIG.
2 is an illustration of a cross-sectional view of an exemplary electromagnetic
tool of the telemetry system of FIG. 1 according to one or more aspects of the
present disclosure.
[0006] FIG.
3 is an illustration of a cross-sectional view exemplary signal receiving
system
of the telemetry system of FIG. 1 according to one or more aspects of the
present disclosure.
[0007] FIG.
4 is an illustration of a perspective view of the exemplary signal receiver
according to one or more aspects of the present disclosure.
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[0008] FIG.
5 is a flow chart diagram of at least a portion of a method according to one
or
more aspects of the present disclosure.
DETAILED DESCRIPTION
[0009] It is
to be understood that the following disclosure provides many different
embodiments, or examples, for implementing different features of various
embodiments.
Specific examples of components and arrangements are described below to
simplify the present
disclosure. These are, of course, merely examples and are not intended to be
limiting. In
addition, the present disclosure may repeat reference numerals and/or letters
in the various
examples. This repetition is for the purpose of simplicity and clarity and
does not in itself dictate
a relationship between the various embodiments and/or configurations
discussed. Moreover, the
formation of a first feature over or on a second feature in the description
that follows may
include embodiments in which the first and second features are formed in
direct contact, and may
also include embodiments in which additional features may be formed
interposing the first and
second features, such that the first and second features may not be in direct
contact.
[0010] This
disclosure is directed to an improved system and method for obtaining downhole
information during a well drilling process. In some implementations, the
system and method
employ a transmitting element on a drill string that communicates
electromagnetic signals
through subterranean formations to a receiver disposed in a separate auxiliary
borehole. The
receiver may be particularly arranged to detect and receive signals, even weak
signals, passed
through the subterranean formation. In this implementation, the receiver is
particularly designed
without exterior material that may insulate or dampen signals that may be
received through the
subterranean formation. That is, in some exemplary implementations, the
receiver comprises a
conductive material forming an external surface of the receiver and disposed
in direct contact
with the subterranean formation. In addition, the conductive material may be
in direct
communication with a center core or wire forming a portion of the wireline
cable. Signal
processing may occur at the surface.
[0011] FIG.
1 shows an example of a drilling telemetry system 100 for signaling in a
subterranean formation. In this implementation, the drilling telemetry system
100 is formed of a
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drilling rig system 102 and a signal receiving system 104. The drilling rig
system 102 includes,
among other components, a transmitter, and the signal receiving system 104
includes, among
other components, a receiver. The drilling rig system 102 may
electromagnetically communicate
information to the receiving system 104. For example, the drilling rig system
102 may transmit
information, such as information relating to the status of the drilling rig
system 102, the
wellbore, or other information to the receiving system 104. In other examples,
the drilling rig
system 102 may emit electromagnetic signals that may be captured by the
receiving system 104
that may allow the receiving system 104 to detect geological formation
characteristics or other
information relating to the geographic material through which the signals are
transmitted.
[0012] The
drilling rig system 102 may be, for example, a land-based drilling rig system¨
however, one or more aspects of the present disclosure are applicable or
readily adaptable to any
type of drilling rig system (e.g., a jack-up rig, a semisubmersible, a drill
ship, a coiled tubing rig,
a well service rig adapted for drilling and/or re-entry operations, and a
casing drilling rig, among
others). The drilling rig system 102 includes a mast 106 that supports lifting
gear above a rig
floor 108, which lifting gear may include a crown block and a traveling block.
The crown block
may be disposed at or near the top of the mast 106. The traveling block may
hang from the
crown block by a drilling line. The drilling line may extend at one end from
the lifting gear to
drawworks, which drawworks are configured to reel out and reel in the drilling
line to cause the
traveling block to be lowered and raised relative to the rig floor 108.
[0013] In
some implementations, the drilling rig system 102 may include a top drive 110
suspended from the bottom of the traveling block. A drill string 112 may be
suspended from the
top drive 110 and suspended within a wellbore 113.
[0014] The
drill string 112 may include interconnected sections of drill pipe 114, a
bottom-
hole assembly ("BHA") 116, and a drill bit 118. The BHA 116 may include
stabilizers, drill
collars, and/or measurement-while-drilling ("MWD") or wireline conveyed
instruments, among
other components. The drill bit 118 (also be referred to herein as a tool) is
connected to the
bottom of the BHA 116 or is otherwise attached to the drill string 112.
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[0015] The
downhole MWD or wireline conveyed instruments may be configured for the
evaluation of physical properties such as pressure, temperature, torque,
weight-on-bit ("WOB"),
vibration, inclination, azimuth, toolface orientation in three-dimensional
space, and/or other
downhole parameters. These measurements may be made downhole, stored in solid-
state
memory for some time, and downloaded from the instrument(s) at the surface
and/or transmitted
real-time to the surface. In the implementations described herein, data may be
transmitted
electromagnetic pulses. In some implementations, in addition to transmission
capability, the
MWD tools and/or other portions of the BHA 116 may have the ability to store
measurements
for later retrieval via wireline and/or when the BHA 116 is tripped out of the
wellbore 113.
[0016] In
the embodiment of FIG. 1, the top drive 110 is utilized to impart rotary
motion to
the drill string 112. However, aspects of the present disclosure are also
applicable or readily
adaptable to implementations utilizing other drive systems, such as a power
swivel, a rotary
table, a coiled tubing unit, a downhole motor, and/or a conventional rotary
rig, among others.
[0017] The
drilling rig system 102 also includes a control system 120 configured to
control
or assist in the control of one or more components of the drilling rig system
102¨for example,
the control system 120 may be configured to transmit operational control
signals to a drawworks,
the top drive 110, the BHA 116 and/or additional equipment. In some
embodiments, the control
system 120 includes one or more systems located in a control room proximate
the drilling rig
system 102, such as the general purpose shelter often referred to as the
"doghouse" serving as a
combination tool shed, office, communications center, and general meeting
place. The control
system 120 may be configured to transmit the operational control signals to
the drawworks, the
top drive 110, the BHA 116, and/or other equipment via wired or wireless
transmission (not
shown). The control system 120 may also be configured to receive electronic
signals via wired
or wireless transmission (also not shown) from a variety of sensors included
in the drilling rig
system 102, where each sensor is configured to detect an operational
characteristic or parameter.
Some example sensors from which the control system 120 is configured to
receive electronic
signals via wired or wireless transmission (not shown) may include one or more
of the following:
a torque sensor, a speed sensor, and a WOB sensor. In some implementations,
the BHA 116
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may also include sensors disposed thereon. Some exemplary sensors include for
example, a
downhole annular pressure sensor 122a, a shock/vibration sensor 122b, a
toolface sensor 122c, a
WOB sensor 122d, a surface casing annular pressure sensor 124, a mud motor
delta pressure
("AP") sensor 126a, and one or more torque sensors 126b. The sensors are
merely examples of
any of a variety of sensors that may be included on the BHA 116, the drill bit
118, and/or
otherwise disposed about the drilling rig system 102.
[0018] In
this exemplary embodiment, the BHA 116 also includes an EM tool 130. The EM
tool 130 may be configured to propagate an electromagnetic signal to convey
information from
the BHA for receipt and analysis by drilling rig personnel. Although
identified as a part of the
BHA 116, in some implementations, the EM tool 130 is disposed elsewhere along
the drill string
112 and down in the wellbore 113. Some implementations include multiple EM
tools 130
arranged to propagate a signal through the subterranean formations. The EM
tool 130 may form
a part of the measurement while drilling MWD tool. In some implementations,
the EM tool 130
may form a part of a collar or stabilizer of the drill string. Some
implementations of the EM tool
130 feature 2-way EM communication, while other implementations include only
transmission
capability. In some implementations, the power, the data rate, and the carrier
wave may be
adjustable while drilling to help transmit through changing formations. In
some
implementations, the EM tool may operate using batteries or a turbine
alternator. The turbine
alternator may enable longer downhole times, and higher transmitting power for
longer periods.
Some implementations may include backup batteries for operation during periods
of no flow.
[0019] FIG.
2 shows an example of an EM tool 130 that may form a part of the BHA 116.
The EM tool 130 may include an electrode 131, a downlink receiver 132, a
transmitter 133, and
the power source 134, such as batteries. The electrode 131 may enable the EM
tool 130 to
communicate with other downhole systems such as, for example, sensing systems
that may be
carried on the BHA. The downlink receiver 132 may be configured to receive
signals and
information from the surface, from other EM tools, or other equipment that may
be in
communication with the EM tool 130. The transmitter 133 transmits EM signals
through
geological formations. In some implementations, the transmitter 133 is a high-
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transmitter configured to automatically select the necessary power usage for
the formation
resistance. This may help extend the life of the power source 134 by reducing
the need to
transmit at full power in certain situations.
[0020]
Returning to FIG. 1, the signal receiving system 104 may be disposed in an
auxiliary
borehole 138. The signal receiving system 104 may include a cable antenna 140
and a signal
processing system 142. In the implementation shown, the cable antenna 140
includes a wireline
cable 144, an electrical cable head 146, and a signal receiver 148. In this
example, the wireline
cable 144 may extend or be wound around a cable coil or reel 150 disposed on
steerable
equipment, such as a working vehicle 152, such as a truck. In the deployed
configuration shown,
the wireline cable 144 may extend from the cable coil 150 through a bore head
154, and into the
auxiliary borehole 138.
[0021] FIG.
3 shows a cross-section of a portion of the signal receiving system 104,
including a portion of the wireline cable 144, the electrical cable head 146,
and the signal
receiver 148. The wireline cable 144 may include a center core 160, a polymer
jacket 162
surrounding the center core 160, and a protective or armor layer 164 disposed
about the polymer
jacket 162. The center core 160 may be formed of a conductive material and may
extend the
length of the wireline cable 144. The center core 160 may be configured to
communicate signals
from the electrical cable head 146 and the signal receiver 148 to the
processing system 142. In
some examples, the polymer jacket is a polytetrafluoroethylene (PTFE)
material, and in some
implementations, the polymer jacket is or includes TEFLON material. The
polymer jacket 162
may insulate or isolate the center core 160 from the armor layer 164. The
protective or armor
layer 164 may be formed of any material that provides protection and strength
to the wireline
cable 144. For example, it may comprise a metal or metal-clad, hollow cable
that provides
sufficient tensile strength to the wireline cable 144. It may be formed of a
plurality of braided
wires or otherwise formed. It may be metal or some other material, including
non-conductive
materials. It may be designed to carry the weight of electrical cable head 146
and the signal
receiver 148. The armor layer 164 may form the outer surface of the wireline
cable 144. In
some implementations, the armor layer is a steel armor layer.
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[0022] The
electrical cable head 146 may be disposed between the wireline cable 144 and
the
signal receiver 148. It may electrically connect the center core 160 to the
conductive material of
the signal receiver 148. In some implementations, electrical cable head 146
may include a
housing 168, an electrical conductor 170, and a cable anchor 172. The housing
168 extends from
a proximal end 174 to a distal end 176. The proximal end 174 may include an
opening 178
through which the wireline cable 144 may extend. The opening 178 may lead to
an anchor
cavity 180 in communication with a passage 182. The distal end 176 of the
housing 168 may
include a threaded tip 184.
[0023] The
electrical conductor 170 may be in electrical communication with the center
core
160 of the wireline cable 144. In some implementations, the electrical
conductor 170 may
extend in the passage 182 from the proximal end 174 to the distal end 176 and
may terminate at
the threaded tip 184. In some implementations, the electrical conductor 170
comprises a spring-
loaded contact 186 projecting from the distal end 176 that contacts the signal
receiver 148.
[0024] The
cable anchor 172 may be disposed within the anchor cavity 180 and may be
connected to the wireline cable 144. In some implementations, the cable anchor
172 is attached
to the armor layer 164 of the wireline cable 144. In some implementations, the
center core 160 is
electrically connected with the electrical conductor 170 through the cable
anchor 172. Some
implementations include an insulative cover about the electrical conductor
170. The insulative
cover may be for example a ceramic or polymeric material that prevents
electrical
communication between the electrical conductor 170 and the housing 168.
[0025] The
signal receiver 148 is connected to the distal end 176 of the housing 168. The
signal receiver 148 may be formed of a heavy, conductive material. In some
implementations,
the signal receiver 148 is formed of a solid stainless steel material. In
other implementations, the
signal receiver 148 is formed of copper, silver, or other highly conductive
material and with
features aiding deployment and contact with formation or casing it is deployed
in. In the
implementation shown, the signal receiver 148 is formed of a solid bulbous
head 190 with sides
192 that taper toward the housing 168, forming a frustum. A threaded bore or
threaded cavity
194 is disposed in the end of the frustum and receives the threaded tip 184 of
the housing 168.
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The signal receiver 148 is formed to abut in direct contact with the walls or
sides of the auxiliary
borehole 138 (FIG. 1) through which it is introduced. Accordingly, the signal
receiver 148 is in
contact with the natural geological formation of the auxiliary borehole 138.
In some
embodiments, signal receiver 148 may contact the hole casing in case of cased
holes. As such,
the signal receiver 148 also acts as the signal receiver from the EM tool 130.
Because the signal
receiver 148 is in direct contact with the subterranean formation, the signal
receiver 148 is
configured and arranged to receive EM signals from the EM tool 130 without
interference or
dampening from unnatural components about the signal receiver 148. For
example, the signal
receiver 148 is free of insulative or protective materials that may interfere
or dampen reception
of signals. Also, it is deployed deeper relative to a conventional EM antenna
at the surface
which is prone to signal attenuation for long reach wells and signal loss in
case of salt domes in
certain basins. Because of this, the signal receiver 148 may be particularly
sensitive to even
weak signals emitted from the EM tool 130 and propagated through the
subterranean formation.
Furthermore, the electrically conductive outer surface (the exterior surface)
of the signal receiver
148 is in direct electrical communication with the electrical conductor 170 of
the cable anchor
172, and with the center core 160 of the wireline cable 144. This electrical
connection may be
free of filtering or other signal distorting components so that the signal
communicated to the
ground surface is the complete and natural signal received at the signal
receiver 148.
[0026] In
this implementation, the shape of the signal receiver 148 may contribute to
the
receptivity of the EM signals. For example, the bulbous head, having a
diameter greater than the
diameter of the electrical cable head 146 insures that a significant portion
of the signal receiver
148 is in contact with the natural subterranean formation. In the
implementation shown, the
signal receiver 148 has the largest cross-sectional diameter of any of the
wireline cable 144 or
the electrical cable head 146. This may help increase the likelihood that the
signal receiver 148
will be in contact with the subterranean formation whether disposed in a
vertical auxiliary
borehole or in a curved or a horizontal auxiliary borehole.
[0027] FIG.
4 shows a perspective view of an example of a signal receiver 148. The signal
receiver 148 in this implementation includes a rounded leading end 196 and a
trailing end 198.
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The tapering sides 192 taper toward the trailing end 198. In this
implementation, the signal
receiver 148 has a substantially teardrop-shape, with the rounded leading end
196 forming the
large diameter bulbous head. A notch 199 may be formed in a side to enable the
signal receiver
148 to be grasped by a tool for threading onto the electrical cable head 146.
In some
implementations, the signal receiver 148 has a diameter in the range of about
2 to 12 inches, and
has a length in a range of about 3 to 18 inches, although larger and smaller
diameters and lengths
are contemplated. In some implementations, the signal receiver 148 has a
diameter in the range
of about 2 to 4 inches and has a length in the range of about 4 to 8 inches.
Furthermore, the
rigidity of the bulbous signal receiver reduces the likelihood of hang-up when
the signal receiver
148 is introduced and fed through the auxiliary borehole 138. For example, a
loose cable or
other flexible component at the distal end may interfere with advancement of
the signal receiving
system 104.
100281 In
some implementations, an insulative covering may isolate the signal receiver
148
from the housing 168 of the electrical cable head 146. In such
implementations, the signal
receiver 148 is still in electrical communication with the electrical
conductor 170 projecting from
the threaded tip 184 of the housing 168. In some implementations, the
electrical conductor 170
is the only component in electrical communication with the signal receiver
148.
100291 The
signal processing system 142 may be disposed at the surface adjacent the bore
hole and may be configured to receive and process signals detected or received
at the signal
receiver 148. In some implementations, the processing system 142 is in direct
communication
with the center core 160 of the wireline cable 144. Accordingly, signals
detected at the signal
receiver 148 may be communicated through the electrical cable head 146 and the
wireline cable
144 to the processing system 142. In some implementations, the processing
system 142 is a
computer having software configured to interpret EM signals received from the
EM tool 130.
100301
Because the signal receiver 148 is able to directly contact the subterranean
formations, and there is no isolation or insulative elements between the
signal receiver 148 and
the center core 160, EM signals may be more easily received and captured for
processing.
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The cable antenna 140 implementation shown in FIG. 3 may be a retrievable type
and may be
easily deployable by means of coil tubing or wireline or the center conductor
can be isolated or
connected to the polymeric material. In some implementations, this receiver
may be used for a
multitude of wells being drilled across the pad as well as nearby pads. In
some implementations,
the wireline cable 144, the electrical cable head 146, and the signal receiver
148 form a simple
conductive connection having no control feedback or logic system. It may
receive and relay the
signal to the surface. In some implementations, the system does not require
electric/magnetic
isolation between the center core and the polymeric jacket.
Furthermore, in some
implementations, the system does not require insulation between the signal
receiver 148, the
electrical conductor 170, and the center core 160.
[0031] FIG.
5 is a flow diagram showing a process of using the drilling telemetry system
100
according to an exemplary implementation. At 502, a user may introduce the EM
tool 130 to the
wellbore. The EM tool 130 may form a part of or be disposed adjacent to a BHA
during a
drilling operation carried out by the drilling rig system 102. In some
implementations, the EM
tool 130 may be spaced apart from the BHA, but may be downhole in the
subterranean
formation.
[0032] At
504, a user may introduce the signal receiving system to an auxiliary
borehole.
Because of the size and shape of the signal receiver 148, the signal receiver
may be in direct
contact with the natural subterranean formation. That is, because the signal
receiver 148 forms
the distal most tip of the signal receiving system, and because the signal
receiver 148 may, in
some implementations, have a diameter larger than other components around the
signal receiver
148, the signal receiver 148 may be in direct contact with the natural
subterranean formation.
Since the signal receiver 148 is also un-insulated, EM signals propagated
through the
subterranean formation may be detected or picked up directly from the
subterranean formation
without interference or dampening from insulative or isolating materials other
than the natural
subterranean formation. The signal receiving system 104 may be introduced to
the auxiliary
borehole with the electrical cable head 146 and the signal receiver 148
suspended from the
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wireline cable 144. The signal receiver and the electrical cable head 146 each
include direct
electrical contact with each other.
[0033] At
506, the EM tool 130 may transmit EM signals through the subterranean
formation. The signals may relate to detected parameters of the wellbore and
its surrounding
environment, of the drilling equipment, or of the subterranean formation.
Accordingly, the
transmitted EM signals may include MWD or LWD information. The EM signals may
be
transmitted while actual drilling is occurring, or may be transmitted during
down times of the
drilling process, such as when stands are being introduced to the drill string
or during other
stoppages in actual drilling.
[0034] At
508, the signal receiver 148 may detect the EM signals directly from the
subterranean formation. Since the signal receiver 148 is particularly shaped
to provide a large
amount of surface contact area, as well as have a wider diameter than other
components of the
downhole signal receiving system, the signal receiver 148 may receive signals
left otherwise
undetected by conventional telemetry systems. In some implementations, the EM
signals are
received only at the signal receiver. In such implementations, the electrical
cable head 146 and
the wireline cable 144 may include insulative or protective materials disposed
about their
respective conductive portions that may inhibit reception of EM signals
transmitted or
propagated through the subterranean formation.
[0035] At
510, the detected signals may be communicated directly from the signal
receiver
through the electrical cable head 146 and the wireline cable 144 to the
processing system 142.
Since the signal receiver is in direct electrical communication with the
electrical conductor of the
electrical cable head 146, and since the electrical conductor 170 is in direct
electrical
communication with the center core 160 of the wireline cable 144, signals may
be communicated
directly to the processing system 142, even when the processing system 142 is
disposed above
ground. At 512, the processing system 142 may interpret the signals at the
surface.
[0036] In an
exemplary aspect, the present disclosure is directed to a drilling telemetry
system that may include an EM tool sized and configured to be disposed on a
drill string and
introduced into a wellbore in a subterranean formation. The EM tool may
comprise a transmitter
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configured to transmit an electromagnetic signal through the subterranean
formation. The
drilling telemetry sytem may also include a cable antenna sized and configured
to be introduced
into an adjacent auxiliary borehole in the subterranean formation and arranged
to receive the
electromagnetic signal transmitted from the EM tool. The cable antenna may
comprise a
wireline cable having a center core, an insulated electrical cable head in
direct electrical
communication with the center core, and an uninsulated signal receiver in
direct electrical
communication with electrical cable head. The uninsulated signal receiver may
have an outer
surface formed of a conductive material and configured to engage against a
natural subterranean
formation.
[0037] In
some aspects, the uninsulated signal receiver has a teardrop shape forming a
bulbous head. In some aspects, the uninsulated signal receiver comprises a
threaded cavity
formed therein for receiving a portion of the electrical cable head. In some
aspects, the cable
antenna comprises a polymeric jacket around the center core, and a protective
layer disposed
around the polymeric jacket. In some aspects, the armor layer is embedded
within and fixedly
attaches the insulated electrical cable head to the cable. In some aspects,
the conductive material
of the uninsulated signal receiver comprises stainless steel. In some aspects,
the EM tool
comprises a transmitter and a power source. In some aspects, the uninsulated
signal receiver has
a diameter of about 2 to about 12 inches, and a length of about 3 to about 18
inches.
[0038] In an
exemplary implementation, a method of using a drilling telemetry system may
include introducing an EM tool to a wellbore; introducing a signal receiving
system to an
adjacent auxiliary borehole; transmitting an EM signal from the EM tool in the
wellbore;
detecting the transmitted EM signal with the signal receiver having a
conductive exterior surface
in direct contact with walls of the auxiliary borehole, the conductive
exterior surface being in
direct electrical communication with an electrical cable head and a wireline
cable; and
communicating the detected EM signal to a signal processing system in
communication with the
wireline cable.
[0039] In
some aspects, detecting the transmitted EM signal with the signal receiver
comprises detecting the transmitted EM signal only at the signal receiver. In
some aspects, the
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method may include performing a drilling operation, and wherein transmitting
the EM signal
from the EM tool occurs during the drilling operation. In some aspects, the
method may include
insulating or isolating a conductive center core in the wireline cable and a
conductor in the
electrical cable head from contact with the walls of the auxiliary borehole.
In some aspects,
communicating the detected EM signal comprises communicating the detected EM
signal
through a conductor in the electrical cable head and through a conductive
center core of the
wireline cable. In some aspects, the exterior surface of the signal receiver
is in direct conductive
electrical communication with the conductor in the electrical cable head. In
some aspects, the
method may include threading the signal receiver on to a distal end of the
electrical cable head to
place a spring-loaded contact in electrical communication with the signal
receiver. In some
aspects, the uninsulated signal receiver has a teardrop shape forming a
bulbous head. In some
aspects, transmitting an EM signal comprises transmitting an EM signal
representative of one or
more detected parameters of the wellbore, an environment surrounding the
wellbore, of the
drilling equipment, of the subterranean formation, or a combination thereof
100401 In an
exemplary aspect, the present disclosure is directed to a drilling telemetry
system that includes an EM tool sized and configured to be disposed on a drill
string and
introduced into a wellbore in a subterranean formation. The EM tool may
include a transmitter
configured to transmit an electromagnetic signal through the subterranean
formation. The
drilling telemetry system may also include a cable antenna sized and
configured to be introduced
into an adjacent auxiliary borehole in the subterranean formation and to
receive the
electromagnetic signal transmitted from the EM tool. The cable antenna may
include a wireline
cable having a center core, a polymeric insulative layer disposed about the
center core, and an
outer protective layer disposed about the polymeric insulative layer. The
cable antenna also may
include an electrical cable head having a housing, an electrical conductor in
electrical
communication with the center core of the wireline and extending through the
housing, and a
cable anchor attached to the outer protective layer and configured to secure
the electrical cable
head to the wireline cable. The housing may have a distal end having a spring-
loaded contact.
The cable antenna also may include an uninsulated signal receiver disposed at
a distal-most end
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of the cable antenna and formed of a rigid, conductive material having a
diameter of about 2 to
about 12 inches. The uninsulated signal receiver may have a conductive outer
surface exposed to
engage against a natural subterranean formation when the cable antenna is
disposed in borehole.
The uninsulated signal receiver may be in direct electrical communication with
the spring-loaded
contact to provide uninterrupted electrical communication between the
conductive outer surface
and the electrical conductor of the electrical cable head.
[0041] In
some aspects, the uninsulated signal receiver has a teardrop shape forming a
bulbous head. In some aspects, the uninsulated signal receiver comprises a
threaded cavity
formed therein for receiving a portion of the electrical cable head.
[0042] In
several exemplary embodiments, the elements and teachings of the various
illustrative exemplary embodiments may be combined in whole or in part in some
or all of the
illustrative exemplary embodiments. In addition, one or more of the elements
and teachings of
the various illustrative exemplary embodiments may be omitted, at least in
part, and/or
combined, at least in part, with one or more of the other elements and
teachings of the various
illustrative embodiments.
[0043] Any
spatial references such as, for example, "upper," "lower," "above,"
"below," "between," "bottom," "vertical," "horizontal," "angular," "upwards,"
"downwards,"
"side-to-side," "left-to-right," "right-to-left," "top-to-bottom," "bottom-to-
top," "top," "bottom,"
"bottom-up," "top-down," etc., are for the purpose of illustration only and do
not limit the
specific orientation or location of the structure described above.
[0044] In
several exemplary embodiments, while different steps, processes, and
procedures are described as appearing as distinct acts, one or more of the
steps, one or more of
the processes, and/or one or more of the procedures may also be performed in
different orders,
simultaneously and/or sequentially. In several exemplary embodiments, the
steps, processes
and/or procedures may be merged into one or more steps, processes and/or
procedures.
[0045] In
several exemplary embodiments, one or more of the operational steps in
each embodiment may be omitted. Moreover, in some instances, some features of
the present
disclosure may be employed without a corresponding use of the other features.
Moreover, one or
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more of the above-described embodiments and/or variations may be combined in
whole or in
part with any one or more of the other above-described embodiments and/or
variations.
[0046]
Although several exemplary embodiments have been described in detail
above, the embodiments described are exemplary only and are not limiting, and
those skilled in
the art will readily appreciate that many other modifications, changes and/or
substitutions are
possible in the exemplary embodiments without materially departing from the
novel teachings
and advantages of the present disclosure. Accordingly, all such modifications,
changes and/or
substitutions are intended to be included within the scope of this disclosure
as defined in the
following claims. In the claims, any means-plus-function clauses are intended
to cover the
structures described herein as performing the recited function and not only
structural equivalents,
but also equivalent structures.
[0047] The
foregoing outlines features of several embodiments so that a person of
ordinary skill in the art may better understand the aspects of the present
disclosure. Such
features may be replaced by any one of numerous equivalent alternatives, only
some of which
are disclosed herein. One of ordinary skill in the art should appreciate that
they may readily use
the present disclosure as a basis for designing or modifying other processes
and structures for
carrying out the same purposes and/or achieving the same advantages of the
embodiments
introduced herein. One of ordinary skill in the art should also realize that
such equivalent
constructions do not depart from the scope of the present disclosure, and that
they may make
various changes, substitutions and alterations herein without departing from
the scope of the
present disclosure.
[0048] The
Abstract at the end of this disclosure is provided to allow the reader to
quickly ascertain the nature of the technical disclosure. It is submitted with
the understanding
that it will not be used to interpret or limit the scope or meaning of the
claims.
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